Overpressures in the Northern Malay Basin: Part 1 - Origin and Distribution

Abstract

Abstract Pore pressure data and sonic velocity-vertical effective stress plots from 31 wells reveal that overpressures in the northern Malay Basin are primarily generated by fluid expansion and located basin-wide within the 2A, 2B and 2C source rock formations. Overpressure magnitude increases towards the basin-centre, with maximum pore pressure gradients of >19.0 MPa/km observed in the southeast of the study area. The overpressures are predominately associated with gas, with gas sampled in over 83% of overpressure measurements. The association of overpressures with gas, combined with a regional geology that largely precludes other fluid expansion overpressure mechanisms, provides the first convincing in-situ evidence for basin-wide gas generation overpressure. Overpressure magnitude analysis suggests that gas generation accounts for approximately 70–50% of the measured excess pore pressure in the region, with the remaining 30–50% being generated by coincident disequilibrium compaction. Thus, the data herein indicates that gas generation, if acting in isolation, produces a maximum pressure gradient of 15.2 MPa/km (0.672 psi/ft), and not lithostatic magnitudes as is often hypothesized. The gas generation overpressures in this study are not associated with a significant porosity anomaly and thus represent a major drilling hazard, with traditional pore pressure prediction techniques underestimating pressure gradients by 2.3±1.5 MPa/km (0.102±0.066 psi/ft). However, pore pressure prediction may be attempted using a calibrated empirical model after careful picking and smoothing of the velocity data. Introduction Abnormally high fluid pressures (overpressures) represent a significant drilling hazard and accurate pore pressure prediction is critical for well planning, casing point selection, drilling procedures and completions (Law and Spencer, 1998; Sayers et al., 2002). However, reliable pore pressure prediction first requires an understanding of the origins and distribution of overpressures and how different overpressure generation mechanisms affect the petrophysical properties of sediments (Hermanrud et al., 1998; van Ruth et al., 2004). Overpressures are generally considered to be generated by two distinct mechanisms, disequilibrium compaction or fluid expansion, which each have different petrophysical signatures and thus require different pore pressure prediction strategies (Tingay et al., 2009). The majority of overpressures observed in sedimentary basins are generated by disequilibrium compaction, in which overpressure is the result of loading (through burial or high horizontal stresses) of effectively sealed sediments (Mouchet and Mitchell, 1989; Osborne and Swarbrick, 1997). Disequilibrium compaction overpressures are typically associated with abnormally high porosities (undercompaction) and, thus, commonly exhibit easily observable seismic velocity anomalies (Mouchet and Mitchell, 1989; Bowers, 1994; Osborne and Swarbrick, 1997). Fluid expansion overpressuring comprises a suite of mechanisms in which the relative volume of pore fluids increases within a confined volume of sedimentary rock (Mouchet and Mitchell, 1989; Bowers, 1994; Osborne and Swarbrick, 1997). Overpressures generated by fluid expansion mechanisms are not associated with a porosity anomaly and are thus more difficult to detect and for pore pressures to be predicted (Miller et al., 2002; Gutierrez et al., 2006). Hypothesized fluid expansion overpressure generation mechanisms include aquathermal expansion, smectite or gypsum diagenesis and gas generation (Mouchet and Mitchell, 1989; Neuzil, 1995; Osborne and Swarbrick, 1997). However, of all proposed fluid expansion mechanisms, only the generation of gas is considered to be able to generate overpressures of significant magnitude (Swarbrick et al., 2002).